docs.cpuc.ca.govdocs.cpuc.ca.gov/word_pdf/AGENDA_DECISION/3609.doc · Web view2005-12-01 · 12....

COM/JLN/hkr DRAFT H-4

12/7/2000

Decision ______________

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking into Implementation of Pub. Util. Code § 390.

Rulemaking 99-11-022(Filed November 18,

1999)

O P I N I O N

(See Appendix A for List of Appearances.)

78714 - 1 -

R.99-11-022 COM/JLN/hkr DRAFT

TABLE OF CONTENTS

Title Page

OPINION...............................................................................................21. Summary.........................................................................................22. Procedural History..........................................................................33. Outstanding Procedural Matters....................................................44. History of Qualifying Facility Contracts.........................................55. Administration of QF Contracts in the Restructured Market.........76. Short Run Avoided Cost of Energy.................................................8

6.1 Options........................................................................................86.1.1 QFs-In/QFs-Out.....................................................................86.1.2 New Entrant.........................................................................86.1.3 Heat Rate Cap/Collar............................................................96.1.4 PX Day-Ahead Price..............................................................96.1.5 Intermittent Resources.........................................................9

6.2 Discussion.................................................................................117. Value of Capacity..........................................................................14

7.1 Statutory Construction of Section 390(d).................................157.2 As-Available Capacity Payments...............................................187.3 Other Measures of Capacity.....................................................18

8. Line Loss Methodology.................................................................218.1 Background...............................................................................218.2 Parties’ Positions......................................................................248.3 Discussion.................................................................................27

9. Functioning Properly Criteria.......................................................3310. Reopener Provision.......................................................................3711. Implementation Issues..................................................................3812. Sierra Pacific and Pacificorp.........................................................39Findings of Fact..................................................................................40Conclusions of Law.............................................................................42ORDER................................................................................................44

Appendix A

- i -


O P I N I O N

1. SummaryThis decision adopts the framework for implementing Pub. Util.

Code § 390,1 which governs payments to qualifying facilities (QFs) receiving short-run avoided cost (SRAC) energy payments. We adopt the day-ahead zonal Power Exchange (PX) market-clearing price as the SRAC energy price, once the Commission makes required findings under Section 390. We conclude that for QFs, whose energy production is a must take resource delivered exclusively to the PX, the PX price represents an “all-in” price, containing both energy and capacity value. Consistent with this finding, we eliminate as-available capacity payments to QFs holding as-available contracts. For QFs receiving firm capacity payments, forecast as-available capacity payments, or forecast as-delivered capacity payments, Section 390(d) governs removal of the value of capacity from the PX price. The statutory language limits our ability to develop a “capacity subtracter” that accurately represents the capacity value in the market. Therefore we adopt the value of capacity definition established by Section 390(d) but we also identify the capacity value we would have adopted, were it not for the statutory limitation.

This decision adopts Generation Meter Multipliers (GMMs) as the transmission line loss factor to be used in calculating QF payments once QFs are paid the PX day-ahead zonal market-clearing price. While QFs continue to receive payments under Section 390(b), we adopt a modified GMM formula for the transmission loss factor of

1 All statutory references are to the Public Utilities Code.

- 2 -


GMM QF/GMM SYS, to be implemented with the first posting following the effective date of this decision.

This decision concludes that if the PX is the market where the utilities procure the majority of their energy requirements and it reasonably represents the costs of other utility purchases, then the PX represents the utilities’ avoided cost and is functioning properly for the limited purpose of paying QFs. This decision passes no judgment on whether the electricity market as a whole is functioning properly or efficiently. We will address whether the criteria for determining if the PX is functioning properly for these limited purposes in phase 2.

2. Procedural History

The purpose of this rulemaking is to implement § 390 by developing a PX-based short run avoided energy cost for purposes of paying qualifying facilities. Part of this process is the determination of any value of capacity embedded in the PX-based SRAC, pursuant to § 390(d). The scoping memo set forth the following additional goals:

(1)review potential modifications to the pricing methodology for as-available capacity payments;

(2)determine whether or not current methodologies for adjusting line losses need to be replaced, and if so, by what methodology;

(3)develop criteria for determining whether the market is functioning properly;

(4)identify situations that would lead to reconsideration of the adopted PX-based SRAC; and

(5)clarify regulatory procedures surrounding the payments.

- 3 -


On February 15 and 16, 2000, Energy Division hosted a workshop on line loss methodologies. Energy Division filed its report on the workshop on April 7, 2000.

Testimony was served on all issues except line loss issues on February 11, 2000. Rebuttal testimony was served on March 6, 2000. Testimony on line loss issues was served on April 28, 2000. Rebuttal testimony on line loss issues was served on May 8, 2000. Nine days of evidentiary hearings were held (April 3-7, April 10-11, and May 11-12). Commissioner Neeper presided at hearing on all nine days. Opening and Reply Briefs were filed by the Office of Ratepayer Advocates (ORA), Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), California Cogeneration Council and Watson Cogeneration Company (jointly CCC), Independent Energy Producers Association (IEP), Cogeneration Association of California, Energy Producers and Users Coalition, Coalinga Cogeneration Company, and Midway Sunset Cogeneration Company (jointly CAC), FPL Energy LLC (FPL), Enron Wind Corporation (EWC), Caithness Energy L.L.C. (Caithness), and California Power Exchange (PX). The Automated Power Exchange (APX) filed an Opening Brief. Final oral argument was held on __________.

3. Outstanding Procedural MattersOn June 14, 2000, CCC filed a motion to set aside submission in

order to enter into evidence certain responses to data requests related to line losses. There was no comment on the motion. CCC’s motion is granted. Appendix A to the June 14 motion will be marked as Exhibit 29 and will be received into evidence as of June 14, 2000.

- 4 -


On June 14, 2000, SCE filed a motion to strike portions of the Opening Briefs of Caithness, EWC, and FPL. EWC responded on June 16, FPL responded on June 29, Caithness responded on June 28. The material SCE seeks to strike is based on the specific record, general facts, or is argument that is appropriately within the scope of briefs. SCE’s motion to strike is denied.

On June 21, 2000, CCC filed a motion to strike portions of SCE’s Opening Brief. SCE responded on June 26. CCC argues that two alternative proposals offered by SCE on brief are not record-based, are untested by cross-examination and do not have comparative pricing information provided. SCE counters that its alternative proposals are “logical extension[s]” of proposals by other parties, with basis in the record. We agree with SCE; the motion to strike of CCC is denied.

4. History of Qualifying Facility ContractsThe Public Utility Regulatory Policies Act of 1978 (PURPA)

obligates utilities to purchase QF power:

“The purpose of PURPA was and remains, among other things, to reduce dependence on foreign energy supplies, to decrease reliance on fossil fuels, to foster the development of renewable technologies, and to encourage reliance on a more diverse mix of resources. To accomplish these goals, PURPA includes mandatory purchase and interconnection provisions governing power purchases by the utilities from QFs.” (EWC, Opening Brief, p. 3.)

Under PURPA, the Commission establishes the avoided cost prices that utilities pay to QFs in California. The federal statute requires the Commission to balance the interests of utility ratepayers and QFs in setting avoided cost prices. As expressed in the Federal

- 5 -


Energy Regulatory Commission (FERC) implementing rules: “Rates for purchases shall:

(i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and

(ii) Not discriminate against qualifying cogeneration and small power production facilities.” (18 CFR 292.304.)

QF pricing must comply with both the requirements of PURPA, as implemented by FERC, and with the Public Utilities Code.

FERC’s regulations under PURPA require that payments made to QFs reflect the full avoided costs of the utility purchasing the QF power. “Avoided costs” are defined by FERC as “the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” (18 CFR 292.101.)

CAC/EPUC provide a good summary of the types of QF contracts.

“In addition to non-standard (negotiated) power purchase agreements, there are four categories of standard power purchase agreements between QFs and the three utilities, Pacific Gas & Electric Company (‘PG&E’), San Diego Gas & Electric (‘SDG&E’), and SCE. Standard Offer No. 1 (‘SO1’) contracts require the utility to purchase energy and capacity from QFs on an as-available basis. QFs with SO1 contracts receive an energy payment based on the adopted SRAC method for energy and an administratively determined as-available capacity payment. Under Standard Offer No. 2 (‘SO2’) contracts, the QF receives an energy payment based on the adopted SRAC method for energy and a separately determined firm capacity payment. These firm capacity payments were determined prior to contract execution based on forecasted avoided generation capacity cost. Standard Offer No. 3 is similar to SO1, but

- 6 -


available only to QF projects of 100 kW or less. Standard Offer No. 4 (‘SO4’) contracts provide for the purchase of long-term firm capacity and energy. The capacity payments under these contracts are based upon an established fixed price. The energy payments are ultimately based upon the Commission determined SRAC of energy. Non-standard, negotiated power purchase contracts contain negotiated prices for energy and capacity which may be indexed to payments made under standard offer contracts.” (CAC/EPUC Amended Opening Brief, June 9, 2000, p. 5.)

Historically, administratively determined SRAC energy payments were contentious. With the adoption of Section 390, the Legislature signaled its intent to move QF payments to market based pricing. At the same time, Section 390 states its intent to eliminate the possibility of double payment for capacity for those QFs with contracts that make firm, forecast as-available, or forecast as-delivered capacity payments.2

5. Administration of QF Contracts in the Restructured MarketQFs receive payments from utilities for both energy and

capacity. Currently the utilities schedule QF power through the PX as a must-take resource and receive payment for that power based on the PX price. The utilities then pay the QFs for their energy deliveries based on the administratively determined SRAC formula in Section 390(b). Section 390(b) established an interim methodology using a

2 Under S04 contracts, QFs had different fixed capacity price options. Some QFs holding S04 contracts are paid firm capacity payments; others are paid forecast as-available or forecast as-delivered capacity payment. Forecast as-available capacity payments are defined and set in the S04 contracts and differ from the as-available capacity payments received by QFs holding S01 and S03 contracts. As-available and as-delivered have the same meaning as it applies to QF contracts. SCE and SDG&E use “as-available” and PG&E uses “as-delivered” to refer to refer to energy and capacity supplied under S01 contracts.

- 7 -


historical benchmark indexed for changes in gas prices. The difference between SRAC payments to QFs (including payments for capacity) and PX revenues associated with QF power is either a transition cost or benefit. The evidence shows that during the period November 1998—December 1999, the Section 390(b) price consistently exceeded the PX market clearing price and resulted in additional transition costs to be recovered.

Section 390(c) allows qualifying facilities to exercise a one-time option to elect to receive energy payments based on the PX market-clearing price upon appropriate notice to the utilities. The statute does not define the market-clearing price. In Decision (D.) 99-11-025, we established procedures to allow for the one-time switch.

6. Short Run Avoided Cost of EnergyOur first task is to develop a PX-based short run avoided energy

cost. Five proposals were advanced in this proceeding.

6.1 Options

6.1.1 QFs-In/QFs-OutCAC and IEP3 propose to establish SRAC energy

payments by adjusting the day-ahead PX clearing price to reflect what the price would have been after removing a specified group of QFs from the resource mix. The CAC and IEP proposals reflect the costs utilities would incur “but for” the presence of QFs in the resource mix, drawing on the Commission’s historical “QFs-In/QFs-Out” method of determining avoided cost. Under a historical comparison, the CAC and IEP methodologies would result in payments to QFs that exceed the PX day-ahead clearing price. (CAC, Ex. 15; IEP, Ex. 18.)

3 In its Opening Brief, IEP has shifted its support to CCC’s proposal.

- 8 -


6.1.2 New EntrantSCE and ORA both propose to base SRAC energy

payments upon the energy-related costs of a hypothetical new market entrant. “The new market entrant is the generator employing the most efficient available technology that can recover its capital and operating costs under current market conditions.” (SCE, Ex. 50, 44:9-11.) SCE and ORA would look to the siting cases pending before the California Energy Commission to determine the operating characteristics of the new market. Using historical data, the new entrant proposals of SCE and ORA, would result in QF payments below the PX day-ahead clearing price for the zone in which the QF is located. (SCE, Ex. 67; ORA, Ex. 103.)

6.1.3 Heat Rate Cap/CollarORA offers a secondary proposal to determine SRAC

energy payments using the PX price capped by the heat rate of the least efficient unit in the market being applied to the Section 390(b) transition energy price. ORA states that implementation of this approach relies on administrative determination of certain elements. (See ORA, Ex. 100, 43:13-15.) In hours when the PX price is below the cap, QFs would receive the PX price, the cap would set the upper bound for the energy price. Drawing on ORA’s “heat rate cap” proposal, on brief, SCE proposes an alternate methodology that would establish a heat rate “collar” to derive an “energy only” value with a cap and a floor price.

6.1.4 PX Day-Ahead PriceA fourth SRAC energy pricing proposal was advanced by

CCC, SDG&E, and PG&E and joined by IEP on brief. These parties propose to set SRAC energy payments equal to the PX day-ahead

- 9 -


clearing price for the zone in which the QFs are located. Possible adjustments for the value of capacity are discussed in Section 7. Adoption of the PX day-ahead price, assuming zero capacity value, would have historically reduced QF payments for SCE and SDG&E and increased them for PG&E compared to the Section 390(b) formula.4

6.1.5 Intermittent ResourcesFPL argues for a different SRAC energy payment for

intermittent resources because of their special operational characteristics. “Intermittent QFs as used in this case refers to wind and run-of-river hydro resources--i.e., those QF resources that cannot control the timing of their output.” (FPL Opening Brief, p. 1.) FPL argues that as renewable resources, wind and run-of-river hydro generators are environmentally preferable to most other types of generation, because neither produces carbon dioxide, NOx, SOx, or particulates, major contributors to various pollution problems. (See FPL Opening Brief, p. 7.)

According to FPL, “(i)f the Commission were to adopt an hourly pricing mechanism . . . for intermittent resources, these resources would be at a significant disadvantage to other generators. Other generators can, to at least some extent, manage the timing of when they supply electricity to the grid . . . . Those generators can maximize production during high-price periods and ramp down during low-price periods, whereas intermittent resources are at the mercy of the wind and the water.” (FPL Opening Brief, p. 4.)

FPL proposes that the Commission retain the current SRAC methodology for intermittent resources. In the event the 4 Over various comparison periods, including all of 1999. (See CCC, Ex. 16, SDG&E, Ex. 69, and PG&E, Ex. 71.)

- 10 -


Commission moves to a PX-based price, FPL recommends use of a monthly weighted-average PX price for intermittent resources. As FPL describes, under the current SRAC transition formula, avoided cost is calculated using several time-of-use periods: peak, partial peak, off peak, and super off peak. Within each time-of-use period, QFs are paid a monthly weighted-average avoided cost. FPL points out that, “no one has asserted that this feature of the current transition formula violates PURPA. Thus, FPL’s proposal to base SRAC payments to intermittent QFs on a monthly weighted-average PX-based price also complies with PURPA.” (FPL Opening Brief, p. 9.)

FPL prepared an exhibit to calculate the costs to ratepayers of its proposal. Exhibit 20 shows increased costs to ratepayers in SCE’s service territory of $5.7 million and $3.9 million in PG&E’s service territory for the period December 1998-–November 1999, compared to an hourly PX-based SRAC. Since SDG&E has no intermittent QFs resources, FPL’s proposal has no impact for SDG&E ratepayers.

SDG&E argues that “while FPL’s proposal would benefit its particular market segment, it would harm others. FPL would have utilities overpay for wind energy. Wind QFs typically produce energy off-peak and therefore an averaged price will pay more over time than what wind energy is worth in the market. On the other hand, solar energy producers, for example, would likely be paid less than market value for their energy since they tend to produce during high peak times. Ex. 55, p. 3. QFs should get the value determined by the market for their power, not some administratively determined price that distorts market signals. And, Sections 381 and 383 already provide financial assistance for these types of QFs.” (SDG&E Opening Brief, p. 18.)

- 11 -


6.2 DiscussionSection 390(c) requires that SRAC energy payments be based

upon the PX clearing price. The QFs-in/QFs-out method proposed by CAC and IEP requires us to assume that a significant block of QF resources (400 average MW in CAC’s proposal and 5000 MWh in IEP’s proposal) act in concert to withhold their energy production from the market. We find these assumptions unrealistic because they overstate the expected impacts in the PX market when a single generator fails to produce. Therefore, the QFs-in/QFs-out methodology, using the PX market clearing price as a starting price, causes this PX-based price to exceed the utilities’ avoided cost.

The SCE and ORA new entrant proposals rely on the expected operating costs of a hypothetical new entrant. Such proposals are long-run avoided cost approaches. Because we are attempting emulate short-run avoided energy costs, the long-run methodology proposed by SCE and ORA is not a reasonable proxy for SRAC. Indeed, the new entrant methodology is only marginally linked to the PX price, upon which Section 390 directs us to base the SRAC energy price. Likewise, the heat rate cap/collar secondary proposals by ORA and SCE are derived from hypothetical “efficient” and “least efficient” generators. The cap/collar establishes limits on the use of the PX price for SRAC energy payments. Although this approach will be PX-based in many hours, like the new entrant methodology, it relies on hypothetical generators to establish an energy value in lieu of the PX price. In many ways, the new entrant and heat rate cap/collar approaches are very similar to the administratively determined SRAC approaches used for many years. They are dependent on input assumptions that have typically been controversial.

- 12 -


The CCC, SDG&E, and PG&E SRAC pricing proposal clearly complies with Section 390(c), as it would set SRAC equal to the PX day-ahead clearing price. In addition, because the utilities are currently required to buy the majority of their electric energy from the PX,5 the PX day-ahead clearing price is a reasonable measure of utility avoided cost. While the utilities do employ more than one PX market and trade in the ISO’s real-time market, more than ninety percent of utility energy purchases have been made from the PX day-ahead market since the market opened. (CCC, Ex. 3, at 23:4-5; SDG&E, Ex. 51, at 7:6-7; PG&E, Ex. 52, at 5.)

We agree that receiving SRAC payments based on an hourly market price could harm intermittent resources. As summarized by FPL, harm to intermittent QFs would arise from volatility of hourly prices because “(1) intermittent resources are not able to control the timing of the output of their facilities in order to maximize production during high-price periods, (2) hourly market prices are volatile, and (3) intermittent resource generation is also volatile, resulting in a more volatile revenue stream than current revenue streams.” (FPL Opening Brief, p. 11)

In its critique of FPL’s intermittent resource proposal, SDG&E argues that certain energy producers, specifically solar producers, would be paid less under FPL’s proposal than if they were paid on an hourly price. QFs who produce power on peak could be

5 See D.95-12-063, as modified by D.96-01-009, at 51, mimeo. D.00-06-034 eliminated the requirement that utilities purchase solely from the PX. Section 355.1, subsequently adopted by AB 2866 (Stats. 2000, Chap. 127, Section 31) prohibits the Commission from implementing the part of D.00-06-034 that allows utilities to purchase from exchanges other than the PX. D.00-08-023 allows PG&E and SCE to purchase energy and ancillary services in the bilateral market within prespecified limits; delivery under such contracts continues to take place in the PX market.

- 13 -


disadvantaged if they were required to take a monthly weighted price. Although SDG&E’s critique would have merit if we were to adopt FPL’s proposal for all resources, FPL proposes that monthly weighted-average prices be available only to wind and run-of-river hydro resources.

We adopt the PX zonal day-ahead market clearing price as the energy price for QFs receiving SRAC energy payments. Not only does this price clearly comply with Section 390 directives, it is also an accurate representation of utility avoided cost under today’s market structure and procurement policies. We find that the societal benefits associated with resource diversity and the environmentally-preferred energy production offered by intermittent resources outweigh the ratepayer cost associated with FPL’s proposal. Therefore, we will allow wind and run-of-river hydro QFs receiving SRAC energy prices to elect, at their option, to receive a monthly weighted-average PX day-ahead price (adjusted consistent with Section 390(d)) in lieu of hourly pricing once the Commission has made the required findings under Section 390(c). We will not retain the current SRAC formula for intermittent resources because it is not a PX-based price. We focus next on how to remove the value of capacity from the PX zonal day-ahead market clearing price, consistent with Section 390(d).

7. Value of Capacity CAC and IEP propose that the language of Section 390(d) be

taken literally and illustrate, by reference to a graph in Exhibit 9, how such value is to be determined. SDG&E and PG&E have proposed to remove the value of capacity, if any, in accordance with the express language of Section 390(d). CCC proposes to adjust the PX day-ahead

- 14 -


zonal market clearing price by “the value of capacity, if any, in the PX price as specified in Section 390(d).” (CCC Opening Brief, p. 21.)

Both ORA and SCE have criticized the method for determining the value of capacity in the clearing price as described in Section 390(d), arguing there is more capacity value in the clearing price than is reflected in the formula described in Section 390(d). As SCE testified, “[t]he price of capacity is typically associated with the fixed costs of operation. (Citation.) It is this formulation of “capacity value” which served as the basis for the capacity payments currently being made under standard offer contracts described in the first sentence of Section 390(d) and in Section 390(e). Such capacity payments are based on the fixed costs associated with the alternative of installing a combustion turbine peaker. (Citation.)” (SCE Opening Brief, p. 24, citations omitted.)

It is a factual determination whether there is capacity value in the PX clearing price separate from the statutory definition. As most parties have acknowledged, the definition of “value of capacity” contained in the state law has, at all times, yielded a value of zero. The record evidence, supports a finding that the PX day-ahead market-clearing price has routinely exceeded conservative administrative estimates of energy costs, and therefore includes non-energy value. “[H]istorical market-clearing prices have frequently contained a ‘value of capacity’ as that concept was used to set capacity payments under the standard offers (S02 and S04) referred to in the statute. As stated by SCE witness Jurewitz:

Certainly, no credible expert today could maintain that the hourly market-clearing prices observed since the beginning of the new market structure in California have simply reflected the marginal operating cost of the least efficient

- 15 -


generator clearing the market and, that therefore, these prices have never reflected any marginal capacity costs.” (SCE Opening Brief, pp. 24-25.)

Indeed, under cross-examination, CCC witness Beach agreed that there are opportunities for PX suppliers to sell energy at prices above their marginal operating cost. (RT 657:23-659:14.) However, in determining the value of capacity for removal, consistent with Section 390(d), we must first look to the statutory language for direction.

7.1 Statutory Construction of Section 390(d)After stating that capacity value should be removed from the

PX-based price, Section 390(d) then describes capacity value. ORA argues that we should not interpret this statutory language to be a definition of capacity value and that we should liberally construe the language in order to adopt a different capacity value.

We addressed statutory construction in D.98-12-067, among others:

“In determining that intent, we first examine the words of the respective statutes: ‘If there is no ambiguity in the language of the statute, “then the Legislature is presumed to have meant what it said, and the plain meaning of the statute governs.” [Citation.] “Where the statute is clear, courts will not ‘interpret away clear language in favor of an ambiguity that does not exist.’ [Citation.]”’ (Lennane v. Franchise Tax Bd. (1994) 9 Cal.4th 263, 268 [36 Cal.Rptr.2d 563, 885 P.2d 976].)” (pp. 18-19.)

Thus, it is well settled that we must turn first to the language of the statute, which must be read such that every word is given its usual import and significance. (Dyna-Med, Inc. v. Fair Employment & Housing Commission, (1987) 43 Cal.3d 1379, 1386-1387, 241 Cal.

- 16 -


Rptr. 67, 70.) There is a presumption that words used twice or more in the same act will have the same meaning. (ICC Industries, Inc. v. United States (Fed. Cir. 1987) 812 F2d 694, 700.)

In its opening statement, ORA conceded “[t]he 390(d) formula’s essential end-result is that PX market-clearing price will be paid as a short-run avoided energy cost to QFs. That exists if we take the express terms of Section 390(d) and apply it very, very strictly.” (RT 21:16-20.) ORA witness Linsey testified that, in order to find ORA’s proposals for the SRAC energy payment consistent with Section 390, the term “value of capacity” would have to be understood to mean different things in the first sentence of Section 390 and in the second sentence of Section 390. (RT 747:25-749:2)

SCE and ORA argue that because the Section 390(d) definition for value of capacity understates the true capacity value reflected in the PX price, Section 390(d) is inconsistent with PURPA’s requirement that QF payments not exceed utility avoided cost. SCE and ORA argue therefore that the Commission cannot simultaneously implement Section 390(d) and PURPA. However, in discharging its obligations in this proceeding, the Commission must comply with Section 390(d), even if it believes that such law conflicts with PURPA.

As CCC points out, “[T]he California Constitution, Article III, section 3.5 specifically provides that, ‘[a]n administrative agency, . . . has no power . . . [t]o declare a statute unenforceable, or to refuse to enforce a statute on the basis that federal law or federal regulations prohibit the enforcement of such statute unless an appellate court has made a determination that the enforcement of such statute is prohibited by federal law or federal regulations.’ Cal. Const. Art III, § 3.5(c); Reese v. Kizer, 46 Cal. 3d 996, 998 (1988). The purpose of this portion of the California Constitution is ‘to prevent agencies from using their own interpretation of the Constitution or federal law to thwart

- 17 -


the mandates of the Legislature.’ Reese, 46 Cal. 3d at 1002. No appellate court has ruled, or even reviewed, the potential preemption of Section 390(d) by PURPA as asserted by Edison and ORA.6” (CCC Opening Brief, p. 26.) We agree that this Commission has no authority to refuse to implement Section 390(d).

We find that the plain reading of Section 390(d) provides a definition for the value of capacity which we must rely on to adjust the PX price for purposes of paying QFs who receive firm, forecast as-available, or forecast as-delivered capacity payments. We will refer to the statutorily prescribed definition for the value of capacity as the “capacity subtracter.” When the law is unambiguous, the Commission has no discretion and must simply apply the law.

It gives us no pleasure to reach this conclusion because, as the record makes clear, the capacity subtracter, defined in Section 390(d), will rarely, if ever, be a number other than zero. The record also makes clear that if a generator can only sell into the PX market, then it must recover all its costs from the PX price, making the PX price an “all-in” price that includes both energy and capacity. Because QFs are must-take resources, scheduled exclusively through the PX, it follows that the PX price includes both energy and capacity value, and that the capacity value is likely to be nonzero in many hours. Therefore, the PX price, adjusted by the Section 390(d) capacity subtracter, will still reflect some capacity value.

Were we not constrained by the statutory definition in the second sentence of Section 390(d), we would adopt a different

6 While the CPUC cannot rule on federal preemption issues, it is proper for the issue to be raised before the administrative agency to preserve the matter for appeal. Delta Dental Plan of Cal., Inc. v. Mendoza, 139 F.3d 1289, 1296 (9th Cir. 1998).

- 18 -


measure of capacity. We will first address as-available capacity payments and then discuss other measures of capacity.

7.2 As-Available Capacity PaymentsIn the Scoping Memo, the Assigned Commissioner expanded

the scope of this proceeding to review the methodology for setting as-available capacity payments. The utilities and ORA argue that the PX price is an “all-in” price that includes value for both energy and capacity. CCC argues that the PX price is an “all-in” price when bidders trade exclusively in the PX. (See CCC Opening Brief, June 1, 2000, p. 46.) CCC argues that because generators may also sell into California Independent System Operator (ISO) markets, other measures of capacity are available. We agree that the PX all-in price does not represent the only measure of capacity when generators can sell their power into other markets. However, because of their must-take status, QF power is bid exclusively into the PX. Utilities must still purchase energy for their full requirements customers from the PX. Under CCC’s logic then, the PX price represents an all-in price for QF generators. For this reason, we will eliminate administratively determined as-available capacity payments in favor of the all-in PX price, once this Commission has made the required findings under Section 390(c).

QFs that continue to sell power to utilities under as-available contracts will be paid the day-ahead zonal PX market clearing price only, without adjustment for the value of capacity, once the Commission has determined the PX is functioning properly under Section 390(c).

- 19 -


7.3 Other Measures of CapacitySCE and ORA, in lieu of developing an approach to remove

capacity from the PX price, developed mechanisms designed to limit SRAC energy payments by attempting to establish an energy value, independent of the PX price. These approaches were described in Section 6.1 above. On brief, SCE proposed an alternative means to remove capacity value from the PX price, based on CCC’s testimony endorsing a 50/50 weighting of hourly spinning and non-spinning reserve prices as the measure of as-available capacity. Under SCE’s alternative, the 50/50 blend of the hourly spinning and non-spinning ISO reserve market prices would represent capacity value and would be removed from the hourly PX zonal day-ahead market-clearing price. Because other parties advocated for a strict interpretation of Section 390(d), no other measures of capacity were proposed.

The spinning reserve market clearing price and the non-spinning reserve market clearing price represent the prices paid by the ISO to generators (or load) to stand by or be available to meet load requirements. The spinning reserve and non-spinning markets are generally considered to be capacity reserve markets.

Only QFs receiving firm, forecast as-available, and forecast as-delivered capacity payments should have capacity value removed from the PX price pursuant to Section 390(d). We must therefore look to prior Commission decisions to determine how such capacity payments were calculated. D.82-01-103 states:

“The firm capacity payment discussed in this section is based on a short-run marginal costs methodology, in which the capacity payment reflects the costs of a shortage.

- 20 -


“Both the firm and the as-available capacity payments ordered by this decision are based on the shortage cost concept.” (8 CPUC2d 20, 58.)

The same decision describes short-run marginal costs in this way:

“[T]he short-run marginal cost of utility electricity production is the highest variable operating cost per unit of electricity produced at a given time plus a shortage cost which reflects the effects of the added increment of production on reserve margins and reliability. As these costs are avoided through purchases of QF power, the purchase price paid to QFs . . . is tied to the short-run marginal cost. This will include an ‘energy payment’ equivalent to the utility’s marginal operating cost and a ‘capacity payment’ equivalent to the utility’s marginal shortage cost.” (8 CPUC2d 20, 41-42.)

Therefore, the capacity payment is to reflect the effect of an added increment of production on reserve margins and reliability. In Exhibit 3, CCC presents its approach to establishing a value for as-available capacity using operating reserve prices in the ISO spinning and non-spinning reserve markets.

Q: Have the ISO and the FERC recognized that operating reserve prices are reasonable measures of the value of short-term, as-available capacity on the ISO grid?

A: Yes. In a recent order, the FERC approved an ISO proposal for the pricing of power that the ISO purchases when it goes outside the market to dispatch a generator, for example, to maintain reliability. For such ‘out-of-market’ calls, the ISO’s payment will include a capacity component equal to the average of the prices for spinning and non-spinning reserves in that hour. The FERC found that this capacity price represented a reasonable compensation to generators for the capacity value of power that the ISO calls on a short-term basis. (CCC, Ex. 3, 34:3-11.)

- 21 -


CCC proposed this 50/50 weighting as a proxy for as-available capacity to be paid in addition to the PX price. SCE instead proposes that we use this proxy to remove the capacity value from the PX price. Because we find that the PX price includes capacity value, we do not adopt CCC’s proposal to make an additional payment for as-available QFs. The question then becomes, is the ISO reserve market a reasonable proxy for the value of capacity that the first sentence of Section 390(d) directs us to remove? In other words, does the average of the ISO spinning and non-spinning reserve prices reflect the addition of an added increment of production on reserve margins and reliability? The ISO’s tariffs define operating reserve as the combination of spinning and non-spinning reserve required to meet Western Systems Coordinating Council (WSCC) and North American Electric Reliability Council (NERC) requirements for reliable operation of the ISO control area. Under WSCC criteria, the ISO must carry specific operating reserve margins based on the amount of generation on the system. We conclude that the prices paid for operating reserves reflects the addition of an added increment of generation on reserve margins and therefore is a reasonable measure of capacity value.

Based on the data submitted in CCC’s comparison exhibit (Ex. 16), adoption of this capacity value measure as a subtracter would have resulted in an energy price between 12% and 59% lower than using the day-ahead PX price without adjustment. If Section 390(d) provided more flexibility regarding how to remove the capacity value from the PX price, a 50/50 weighting of the spinning reserve and non-spinning reserve prices would be an attractive option.

- 22 -


8. Line Loss Methodology

8.1 BackgroundThe term “line losses” refers to the power losses that occur

when electricity is transmitted over power lines. PURPA established that, to the extent practicable: “the costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility, if the purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount of electric energy or capacity” (18 CFR 292.304(e)(4)) should be incorporated into avoided cost payments.

D.82-12-120, D.84-03-092, and D.87-12-066 established the methodology for line losses for QF payments. Different line loss adjustment factors were established for different usage periods, such as peak, mid-peak, off-peak. Line loss factors greater than one indicate that QF production causes a reduction in utility system line losses, while line loss factors less than one indicate that QF production causes an increase in utility system line losses. For QFs connected to the grid at the transmission level, average transmission loss factors (TLFs) were set at 1.023 for Edison, 1.025 for SDG&E, and 1.000 for PG&E. For QFs connected at the primary distribution level, distribution loss factors (DLFs) were set at 1.026 for Edison, 1.06 for SDG&E, and 1.000 for PG&E.7

These loss factors were established on an interim basis, with the expectation that more definitive studies would lead to a more accurate line loss methodology. As the Commission stated, “[o]ur decision reflects the inconclusiveness of the record on line losses and 7 These DLFs include the effect for both transmission and distribution avoided line losses.

- 23 -


our struggle to develop an appropriate interim solution until the line losses studies required of all three utilities are completed, reviewed, and approved.” (D.84-03-092, p. 37.) The expected review and approval of these studies has never occurred, and all but one of the loss factors have been in place since.

Seeking to revise both the TLFs and the DLFs, SDG&E filed Application 98-06-045 and proposed to replace the existing TLF values with generation meter multipliers (GMMs).8 GMMs were developed and are used by the ISO to determine the impact on system line losses caused by generation from a particular generator. GMMs are calculated for each generator bus and each intertie9 every hour. The GMM’s are first forecasted and published seven days in advance. An update “hour-ahead” GMM is also published. The hour-ahead GMM is also known as the ex post GMM. (See Workshop Report, Appendix C: ISO Presentation on GMMs, p. 4.) The ISO and PX use GMMs for system balancing and settlement purposes.

The Commission rejected SDG&E’s GMM proposal, noting that:

“SDG&E has not demonstrated that these factors no longer reflect avoided line losses on its system, or that the generator meter multipliers of the Independent System Operator (ISO) are more appropriate to use for short-run avoided cost calculations.” (D.99-03-021, p. 1.)

For the same application, SDG&E performed a new study of distribution-level QF line losses. Consequently, the Commission approved SDG&E’s request to switch the DLF value to 1.00. Functioning differently from the old DLF, the new DLF of 1.00 is

8 Some documents use the term “generator meter multiplier” while others use “generation meter multiplier.”9 An intertie is a border point between adjacent transmission grid territories.

- 24 -


multiplied by the TLF in order to obtain the over-all line loss adjustment for distribution level QFs. To avoid constraining future regulatory activity, the decision also noted:

“. . . nothing in this decision precludes any party from bringing up methodological proposals related to line losses, including those considered in this proceeding, in the PU Code Section 390 proceeding opened pursuant to D.99-02-085.” (Ibid., p. 19.)

As directed in the rulemaking, Energy Division convened workshops and issued a workshop report addressing issues pertaining to line losses. Prior to the workshop, parties filed comments, addressing the topics set forth in the Scoping Memo. The workshop focused on developing an understanding of the existing treatment for line losses, proposed alternatives, and criteria to be used in choosing a methodology.

One of the goals of the workshop was to understand how the ISO calculates GMMs. An ISO representative presented the ISO methodology and answered questions from workshop participants. Each GMM is equal to one minus the scaled marginal loss factor. The scaled marginal loss factor is equal to the full marginal loss factor multiplied by a scaling factor. To obtain the full marginal loss factor, the ISO models an increment of power from a generator, and calculates the increase (or decrease) in system line losses that would occur if this increment of power were spread over the entire ISO grid proportionately to where the existing load is. The scaling factor (with a typical value of about 0.55) is the ratio of the system losses divided by the sum of the products, for each generator, of its full marginal loss factor times its generation level. Workshop participants discussed the validity of modeling generation as being spread

- 25 -


throughout the grid, with no bias toward local consumption, as well as the validity of scaling of marginal loss factors. SDG&E’s representative presented a February 2000 study of the effect on system line losses from the four SDG&E transmission level QFs.

Although the workshop furthered understanding of the GMM methodology, it did not produce a consensus for the treatment of line losses. The workshop report reflected this lack of consensus, cited areas that required further investigation, and made recommendations.

8.2 Parties’ PositionsORA, SCE, SDG&E, and PG&E favor use of GMMs to replace

the current TLFs. As alternatives, SDG&E proposes adoption of the TLFs obtained from its recent line losses study or a TLF value of 1.00. PG&E also does not object to keeping its current TLF value of 1.00. These parties claim the following advantages for the GMM methodology:

1. GMMs have been developed and are calculated by the ISO, a neutral, knowledgeable party;

2. GMMs are specific to individual QFs, and consequently more accurate than any single number applied to all QFs;

3. GMMs vary by hour, and thus more accurately reflect the impact on line losses;

4. GMMs have been developed expressly to calculate the impact on system line losses due to power inputs from a given generator;

5. GMMs are being used by the market for purposes of calculating line losses; and

6. GMMs are readily available, and practical.

IEP, EWC, FPL and Caithness favor maintaining the status quo, citing the lack of a conclusive challenge to the existing methodology and pointing out weaknesses in all of the proposed alternatives. IEP

- 26 -


claims that no party has successfully impugned the validity of the existing TLFs. IEP also argues that the proposed GMM method violates Commission Rule 74.3.10

Caithness objects to the use of GMMs, arguing that GMMs do not account for long-term resource decisions made in the 1980s that were responsible for determining the utilities’ avoided costs today. Caithness also raises technical objections to the new SDG&E study, which calculates TLF values of approximately 1.005, significantly lower than the values currently in place. Caithness also argues that the Commission must consider the plight of remotely located alternative resources such as wind, solar, and geothermal who would likely be hit hard financially by the adoption of GMMs.11 Caithness suggests that this result would be counter to California legislative policy, which is to encourage alternative generation.

CCC raises three main objections to the use of GMMs. First, CCC objects to how the ISO model spreads the incremental generation over the entire grid without giving preference to close-at-hand load, which they maintain would be a more realistic assumption. Second, CCC maintains that as a result of the ISO model’s spreading the incremental generation over the grid, certain remotely located generators serving local load will be treated inaccurately and unfairly. Third, CCC argues that by forming GMMs from scaled marginal loss factors, instead of from full, unscaled marginal loss factors, the GMMs dilute the effect that a given generator has on the system line losses.

10 IEP presented this argument in a motion to strike prepared testimony. The assigned ALJ properly denied IEP’s motion in a June 20, 2000 Ruling.11 Remotely located units typically entail higher line losses and typically have lower GMMs.

- 27 -


CCC developed a two-part proposal--one for QFs in general, and the other for remote QFs serving local loads. CCC’s direct testimony derives a general loss factor of GMMqf + d * (GMMqf – GMMsys) where: d is the inverse of the scaling factor that the ISO now uses for calculating GMMs, GMMqf is the GMM value for the individual QF, and GMMsys is the system average GMM. For remotely located generators serving local load, CCC derives a loss factor of d - GMMqf * (d – 1).

Although the workshop report concluded that there was a need for more information regarding DLFs, parties declined to elaborate in their testimony and briefs. SCE proposes that the product of its Wholesale Distribution Access Tariff (WDAT)12 and the appropriate GMM be the DLF. SDG&E proposes no change to its DLF of 1.0, which equals its WDAT. PG&E uses a DLF of 1.00 for its QF payments and proposes no changes, but uses different multipliers in its Wholesale Distribution Tariff.13 Other parties have been largely silent regarding DLFs, although Caithness believes that WDAT-based DLFs should be stand-alone numbers, and should not be multiplied by any other factors (such as GMMs). (Opening Brief, p. 19.)

8.3 DiscussionWe begin our discussion by reviewing whether the existing

methodology for addressing line losses for transmission level QFs is acceptable. The evidence indicates that it is not:

12 For subtransmission level generators, Edison’s WDAT multiplier is 1.0112. For primary distribution level generators, the multiplier is 1.0373. (Workshop Report, Appendix E, last page.)13 For primary distribution system generators, PG&E makes an energy loss adjustment of 1.25%, while for secondary distribution system generators, an adjustment of 3.41% is made. These correspond to DLFs of 0.9877 and 0.9670, respectively. (PG&E Wholesale Distribution Tariff, Attachment D.)

- 28 -


1. No party presented an explanation for the discrepancy between PG&E’s TLF (1.000) and the TLFs in place for SDG&E (1.025) and for SCE (1.023);

2. The recent SDG&E TLF study suggests that the existing TLFs in place for SDG&E are much too high, leading to significant ratepayer losses;

3. D.99-03-021 explains that SDG&E’s and SCE’s current TLFs were based on a study that “assumed that all of the marginal line losses would be avoided by the operation of the QFs” (p.8), a difficult assumption to justify; and

4. Existing TLFs treat QF line losses in the aggregate, leading to a less fair and efficient outcome.

We conclude that replacing the existing TLFs with a simple factor of 1.000, unless there is a better methodology available, would be preferred to the existing factors. With the advantages noted above, GMMs appear to provide a superior methodology. First we examine the various arguments against GMMs more fully.

Caithness claims that the GMM does not address the long-term perspective. In order to perform the analysis proposed by Caithness, the Commission would need to speculate as to the resource procurement choices that would have been made in the 1980s, were it not for the QFs. This approach is unnecessary, as the application of line loss factors is for purposes of paying SRAC payments which clearly calls for a short-run perspective. Although we desire to promote renewable resource development, which often occurs in remote locations, there is no requirement under PURPA, or under California law, that alternative resource QFs receive special treatment for line losses.

CCC argues that the way in which the ISO model spreads incremental load over the entire grid without giving extra weight to nearby load is unrealistic. This criticism has merit. However, all

- 29 -


models that allocate the incremental, or marginal, impact among various agents require approximating assumptions. A hypothetical raised at hearing demonstrates the problem. In the hypothetical, two generators are remotely located, and serve local load that is unable to consume all of the power from these generators. CCC witness Beach conceded that there a number of valid ways to allocate the system line losses impact in this example. (RT 862:7- 865:17.) There does not appear to be a unique, correct solution. The GMM methodology is one of the reasonable ways to allocate system losses.

A remotely located generator serving local load presents equity concerns regarding application of the GMM methodology. However, during the proceeding, no remote QF solely serving local load was identified. As discussed below, we are not convinced that the alternative approach proposed by CCC, which calls for a different formula to be applied to remote QFs serving local loads, is correct. Furthermore, the CCC proposal raises significant implementation difficulties.

Regarding scaling of marginal loss factors, it has not been demonstrated that “scaled” GMMs are wrong, or that “un-scaling” the GMMs is the right approach. In the ISO’s Report to the Federal Energy Regulatory Commission: Studies Conducted Pursuant to the October 30, 1997 Order (December 1, 1999, p. 2), it states that scaling is necessary to avoid overpayments for line losses.14 Scaling is an integral part of the GMM methodology.

We will not adopt the model proposed by CCC. CCC’s proposed differential line loss treatment for remote QFs and for QFs close to the load center appears tailor-made to maximize QF SRAC

14 We take official notice of this report.

- 30 -


payments. Furthermore, the model contains numerous assumptions with which we are not comfortable. Some of these assumptions are:

1. Output from a given QF is treated separately from other generators (CCC Ex. 17, p. A-1);

2. The marginal loss rate for the QF is assumed to be constant (Id.);

3. The Total Avoided Costs equation incorporates the very GMM-based energy payments CCC is attempting to replace (Id., pp. A-3, B-1); and

4. CCC uses the same expression for marginal losses (MLqf) for remote QFs as was developed for the standard QF scenario (Id., p. B-1.).

SDG&E is currently contesting the GMM scaling of marginal loss factors before FERC. Despite the limitations it finds with the current GMM methodology, SDG&E supports the FERC-adopted GMM methodology as the best choice to account for line losses for QF payment purposes. We expect that the GMM methodology may be revisited and refined from time to time by the FERC, and we welcome this process. Proposals to modify the GMM methodology itself should be directed to FERC.

We accept that the GMM is the best method available for measuring the impact on system line losses from an individual generator, but this is not exactly what PURPA calls for. PURPA calls for an adjustment to SRAC payments that will reflect the impact on system line losses as compared to the impact that would have occurred had the utility procured its power elsewhere.

For the case where the SRAC is PX-based, the treatment of line losses is simple. The PX procures power, ascribes line losses to each generator using GMMs, and passes these costs along to buyers in the market. Because each generator bidding into the PX market adjusts

- 31 -


its bid to account for the GMM the PX will apply to the sale, the PX market price will reflect this collective bidding behavior. The resulting PX price reflects GMMs of all generators, thus, the clearing price reflects the system average GMM. That is, the PX clearing price reflects the cost of production as well as the cost of line losses. The PX then pays the generator the PX price times the generator’s GMM. This is exactly the cost the PX avoids by purchasing from that generator. The line loss effect is captured entirely by the GMM when the SRAC is PX-based.

Unlike the PX price, the administratively determined SRAC, reflects only the cost of production. The simple GMM, when applied to the current administratively determined SRAC, fails to compare the individual QF’s line losses to the line losses that would have occurred had the utility procured its power elsewhere. Under PURPA, the impact on system line losses due to generation by the individual QF must be directly compared to the system average GMM, which represents the impact on system line losses due to all of the other generation. This principle was demonstrated during cross-examination of SCE witness Mayfield.

Q: . . . You state, The generator's hourly GMM will be higher relative to the average GMM when the energy it delivers to is [sic] ISO grid decreases average transmission losses and lower than the average when the energy it delivers increases transmission losses. Now, as I understand it, this would mean that when a QFs GMM is higher than the ISO average GMM, the QF is providing line loss savings to the utility; is that right?

A: Yes.

Q: And under PURPA, the QF should be compensated for those savings, correct?

- 32 -


A: That's my understanding. (RT 1008:15-27.)

Therefore, if a QF has a GMM of 0.99 when the system average GMM is 0.98, the QF should receive a one percent credit for the line losses that its production helps the utility avoid. In other words, its TLF should be approximately 1.01, the QF’s GMM divided by the system average GMM. This is the same proposal made by Energy Division’s Workshop Facilitator James Loewen during the Line Losses Workshop and described in the Workshop Report. (P. 25.) In equation form, the new TLF equals GMMQF / GMMSYS. For simplicity of implementation, the simple average of all GMMs can be used to calculate GMMSYS. Since actual (“ex post”) GMMs are already listed on the ISO web site, implementing this approach will be simple and will not require any change in ISO procedures.

We will adopt GMMs as the TLFs once the Commission has made the required findings under Section 390(c) and QFs are paid a PX-based energy price. Until that time, effective with the first posting following this decision, we adopt a TLF equal to GMMQF/GMMSYS.15 QFs who have elected to switch to a PX-based SRAC, pursuant to D.99-11-025, should have their GMM applied to account for line losses, effective immediately.

Regarding DLFs, should we choose to rely on the utilities’ WDAT factors, we face two concerns:

1. Disparity among the utilities’ WDAT factors for distribution level generators;16 and

15 On July 28, 2000, SCE filed a petition to modify D.96-12-028, the decision implementing the transition formula set forth in Section 390(b). That petition was transferred by ruling to this docket. Our adoption of this TLF formula for QFs paid under the transition formula disposes of the relief sought in footnote 4 of the petition.

- 33 -


2. Lack of clarity as to whether the WDAT should be multiplied by the TLF to arrive at the correct total loss adjustment factor.17

The record provides no information as to why the factors vary so significantly between utilities or whether non-QF generators connected at the distribution level are compensated based on the GMM multiplied by the WDAT, or only on the WDAT.

Currently, the total loss factor for distribution-level QFs on PG&E’s system is 1.000; PG&E’s TLF is also 1.000. On SDG&E’s system, the DLF is currently 1.000, and it is multiplied by the TLF to establish the total loss factor for payments to distribution-level QFs. SDG&E’s DLF is the only DLF that has been updated based on a recent study and equals the WDAT. (See D.99-03-021.) SCE proposes to multiply its WDAT by the TLF to arrive at the DLF. We adopt the WDAT of SDG&E and SCE as the DLF, to be multiplied by the TLF, to arrive at the total loss factor for distribution-level QFs. This change should be effective the first posting after the effective date of this decision. Because we cannot explain the difference in the WDAT of PG&E, we retain the existing DLF of 1.000 for PG&E, to be multiplied by the TLF, to arrive at a total loss factor.

9. Functioning Properly CriteriaPub. Util. Code § 390(c) states:

“The short-run avoided cost energy payments paid to nonutility power generators by electrical corporations shall

16 We take official notice of the Wholesale Distribution Tariffs on file with FERC for SDG&E, SCE, and PG&E. According to the tariffs, the following WDAT factors apply for each utility: SDG&E – 1.000; SCE – 1.0112 and 1.037; and PG&E – 0.9877 and 0.9670. 17 SCE proposes to multiply its WDAT values times the GMM of the appropriate bus. Caithness argues that the WDAT values should not be multiplied by any other factor.

- 34 -


be based on the clearing price paid by the independent Power Exchange if (1) the commission has issued an order determining that the independent Power Exchange is functioning properly for the purposes of determining the short-run avoided cost energy payments to be made to nonutility power generators, . . . “

The first question we must address as we develop criteria for whether the PX is functioning properly is the scope of our inquiry, in other words, is this a narrow review for QF pricing purposes only or is our review a judgment on the entire electricity market? As the PX points out, “(t)he narrow focus of the statute indicates that the Commission’s inquiry here is not an assessment of the functioning of the Cal PX for all purposes.” (PX Opening Brief, June 1, 2000, p. 2.) No party appears to dispute that our inquiry should be narrowly focused. We agree and take this opportunity to make clear that the criteria we adopt here are not the proper criteria for judging the broader electricity market success or failure. Our inquiry will focus on whether the PX is functioning properly only for purposes of determining SRAC prices paid to QFs.

The second question we must confront is raised by SCE, who states “the functionality determination is linked to implementation of a market-based SRAC. Thus, to the extent the SRAC methodology accounts for the market distortions identified . . . in this proceeding, the Commission may conclude . . . the market is ‘functioning properly’ for the limited purpose envisioned by Section 390(c).” (SCE Opening Brief, June 1, 2000, p. 76.) In effect, SCE argues that we need not develop stringent criteria to measure whether the PX is functioning properly because the PX-based pricing methodology we adopt should correct for market distortions. ORA agrees with SCE (see ORA Opening Brief, June 1, 2000, p. 46). CCC, on the other hand, argues

- 35 -


that “the best way to account for . . . claimed market distortions is to wait until those distortions have been largely mitigated through adoption and implementation of reasonable functioning properly criteria . . . .” (CCC Reply Brief, June 14, 2000, p. 10.)

The language of Section 390(c) does not instruct the Commission to establish a pricing methodology that corrects for market imperfections, rather it instructs us to implement payments based on the PX clearing price if we have determined the PX is functioning properly for the limited purpose of determining SRAC prices paid to QFs.

Parties have proposed numerous criteria for the Commission’s consideration and generally support the following five criteria as the minimum necessary to find that the PX is functioning properly:

(1) PX market clearing prices result from a transparent process and are published for each day;

(2) PX market clearing prices are based on the bids of available demand and supply;

(3) There is enough liquidity so that PX market clearing prices reflect market conditions;

(4) Buyer and seller market power does not exist; and

(5) Monitoring and regulation of the PX market is occurring.

Criteria 1 and 5 are self explanatory and easily determined on their face. Criteria 2, 3, and 4 are more qualitative in nature. Parties have suggested various ways to measure whether Criteria 2, 3, and 4 have been met. For example, CCC proposes five specific measures designed to address market power, liquidity, and demand

- 36 -


responsiveness. In addition, other parties propose various criteria that relate to transition period rules, the rate freeze, and the end of the requirement that utilities buy from the PX.

Criteria 2, 3, and 4 might be appropriate to judge whether the electricity market as a whole is functioning properly or whether the PX market is workably competitive, but neither of these tasks is before us. Instead we must determine whether the PX is functioning properly for the purpose of determining SRAC energy payments to QFs. Whether the market as a whole is operating efficiently is not a measure of whether the PX price represents utility avoided cost. As stated on brief, “PG&E interprets the ‘functioning properly’ requirement to mean that . . . the PX’s market-clearing price must accurately reflect the competitive price for energy in the new marketplace before the PX may appropriately be used as the proxy for the QF’s contractually specified energy pricing.” (PG&E Opening Brief, June 1, 2000, p. 3.) In its opening statement, SDG&E said “today 30 million California consumers are paying energy prices in their electric rates based on the PX price. Electric generators are being paid the PX price. . . . In such circumstances, if this Commission . . . finds that the PX isn’t working even though generators are currently paid the PX price, the California consumers are paying the PX price, someone’s going to have lots of explaining to do. It just flies in the face of common sense.” (RT 7: 3-22.)

This proceeding is not intended to be a judgment of the overall fairness of the PX pricing mechanisms or the behavior of its participants. In recent months, prices in the PX day-ahead market and other wholesale electricity markets in California have skyrocketed. These high prices have caused considerable hardship

- 37 -


for ratepayers in the SDG&E territory, and led to severe dislocations throughout the market. We have taken a number of steps to address the problems (D.00-08-021, D.00-08-023, D.00-08-037, and I.00-08-002), and we are working with the PX, the ISO, the Legislature and other organizations to craft responsible solutions.

Nevertheless, the instant proceeding is intended to determine if the PX is operating properly in a different sense, not directly related to the measurement of increased rates and volatility in the market. Instead, we consider here whether the PX, in particular, the PX day-ahead market, is doing what it is supposed to be doing: setting a market clearing price that allows utilities to purchase power for their bundled customers. In this regard, SDG&E is correct that our purpose is served by observing that this is exactly what has occurred. Since April 1, 1998, the PX has never failed to perform its assigned function. If this were our only criterion for determining the functioning properly question, we could answer in the affirmative here and now.

We note that the utilities have substantially been constrained to purchase nearly all of the their power needs from the PX day-ahead market until recently. In recent decisions (D.00-06-034 and D.00-08-023), this constraint has been lifted to some degree by allowing expanded use of the PX block-forward market and adoption of bilateral contracting authority within specified limits. Therefore, for purposes of determining if the PX is functioning properly, it is necessary, but not sufficient, to note that the PX has been performing its assigned function. Another element must be a comparison of the prices in the PX day-ahead market with alternative prices available to utilities. Clearly, it is possible that the PX day-ahead market

- 38 -


continues to function, the utilities continue to purchase through it because of a continuing mandate, and the prices in that market are out of line with other available or potential wholesale electric markets. We therefore agree with PG&E’s point that the PX’s market-clearing price must also accurately reflect the competitive price for energy in California. Further, if the utilities are allowed to procure power beyond the PX day-ahead market, they may choose to use or not to use that market. It is appropriate to observe this behavior, for if the utilities choose not to use the PX day-ahead market, this is a good sign that that market is not functioning properly.

Therefore, we have reached the conclusion that, in lieu of the five criteria cited above or other criteria proposed by parties, there are three criteria that we will adopt in order to determine that the PX is functioning properly for the limited purposes of this proceeding. All of these criteria must be met to satisfy our inquiry. The criteria are: a) the PX day-ahead market must provide an ongoing market-clearing price, and b) the PX day-ahead market must be the market where utilities procure the majority of energy for their customers, and c) the PX day-ahead market must reasonably represent the costs of other allowable utility purchases. If the PX day-ahead market meets these criteria, then it fairly represents the utilities’ avoided cost, and it is functioning properly for the purposes of QF payments. In Phase 2, we will evaluate whether these criteria have been met and review whether the utilities have met additional standards set forth in Section 390 (c). The assigned ALJ is directed to hold a prehearing conference within 45 days of the effective date of this decision to establish the schedule for Phase 2.

- 39 -


10. Reopener ProvisionWe have adopted the PX day-ahead market clearing price as the

short-run avoided cost of energy. We have done so because the PX price clearly complies with Section 390(c), and because more than 90% of utility purchases are made in the day-ahead market. If significant percentages of utility purchases move to other markets, it makes sense to revisit whether the PX day-ahead price continues to properly represent utility avoided cost. The record does not provide specific guidance regarding the level at which purchases outside of the day-ahead market should be considered grounds for revisiting or modifying our selection of the PX day-ahead price. In addition, in a workably competitive market, prices for similar products should converge (CCC Ex. 3, 13:11-14), so the PX day-ahead price may still represent a reasonable approximation of utility avoided cost even if large amounts of energy are purchased outside the day-ahead market. Instead of adopting a specific reopener provision we direct the utilities to alert us, through a filing in this docket or other appropriate docket if this proceeding is closed, when on average, more than 50% of their purchases are outside of the PX day-ahead market over the prior six months. The filing should include an assessment of whether the PX day-ahead price continues to represent the utility’s avoided cost or whether a new PX-based price should be considered. Other parties may also make a filing in this, or other appropriate docket, if they believe the functioning property criteria are no longer met.

11. Implementation IssuesToday SRAC energy prices are posted monthly. Upon

determination that Section 390(c) has been satisfied, QFs (with the exception of wind and run-of-river hydro) will be paid on the basis of

- 40 -


an hourly price. Parties did not address the procedures for posting hourly prices (or monthly prices for wind and run-of-river hydro) using the PX price or GMMs. Parties should address posting procedures in Phase 2. Likewise, parties did not address whether revisions to any accounting procedures are required by the move to a PX-based price. Parties should be prepared to address this issue at the Phase 2 prehearing conference.

During the proceeding there was some discussion of the cost associated with implementing various options. Because we adopt a pricing approach that relies on publicly available information sources, there is no incremental cost for the inputs to the pricing formula. Because of the move from a monthly posting to payments based on hourly prices, there may be some additional cost associated with administering the QF contracts. Implementation costs will be evaluated for reasonableness in the Annual Transition Cost Proceeding where QF contract administration is already considered.

In R.99-11-022 we indicated that the price we adopt in this decision will serve as the basis for the true-up for one-time switcher adopted in D.99-11-025. The PX-based price, adjusted consistent with Section 390(d), that we adopt today is the same price we adopted in D.99-11-025. The record in this proceeding is clear that the value of capacity, as defined by Section 390(d), has been zero since D.99-11-025 was issued. For that reason, no true-up is required and payments made subject to the one time switch should be considered final.

Some QF parties have proposed that we require utilities allow QFs the option to bid their output into the market rather than have the utilities schedule the power. This subject was not within the scope of the proceeding. However, we note that QFs are free to

- 41 -


engage in discussions with utilities to modify the terms of their contracts in this manner at any time. We will not require the utilities to offer such an option at this time.

12. Sierra Pacific and PacificorpIn R.99-11-022 we named Sierra Pacific Power Company (Sierra)

and Pacificorp respondents to this rulemaking. Sierra appeared at the prehearing conference; Pacificorp did not appear. Neither company sponsored testimony or prepared briefs on these matters. In the scoping memo, the Assigned Commissioner stated that all respondent utilities would be subject to our decision implementing Section 390. Sierra and Pacificorp should make payments to QFs receiving SRAC payments consistent with this order.

Comments on Draft DecisionThe draft decision of the ALJ in this matter was mailed to the

parties in accordance with Section 311(d) of the Public Utilities Code and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed on , and reply comments were filed on .

Findings of Fact1. PURPA obligates utilities to purchase QF power.2. During the period November 1998 through December 1999 the Section 390(b) price consistently exceeded the PX market clearing price.3. The QFs-In/QFs-Out methodology proposed by CAC and IEP results in payments to QFs that exceed the PX day-ahead clearing price.4. The new entrant proposals of SCE and ORA result in payments to QFs below the PX day-ahead clearing price.

- 42 -


5. Adoption of the PX day-ahead price in 1999 would have resulted in lower QF energy prices, as compared to the Section 390(b) formula, for SCE and SDG&E.6. Adoption of the PX day-ahead price in 1999 would have resulted in higher QF energy prices, as compared to the Section 390(b) formula, for PG&E.7. Wind and run-of-river resources cannot control the timing of their generation output.8. Wind and run-of-river hydro resources do not produce NOx, SOx, or particulates.9. An hourly pricing mechanism would disadvantage intermittent resources.10. From December 1998--November 1999, adopting a monthly weighted-average PX price for wind and run-of-river hydro resources would have cost an additional $9.6 million compared to paying an hourly PX price. 11. The new entrant proposals are not based on the marginal generating unit but on a hypothetical new entrant.12. The new entrant proposals are only marginally linked to the PX price.13. The new entrant and heat rate cap/dollar proposals rely on administratively determined assumptions to operate.14. More than 90% of utility energy purchases have been made from the PX day-ahead market since the market opened.15. The PX day-ahead market clearing price has routinely exceeded conservative administrative estimates of energy costs.16. The PX day-ahead market clearing price includes non-energy value.

- 43 -


17. The value of capacity as defined in Section 390(d) has, at all times, yielded a value of zero and is unlikely to yield any other value.18. The PX price represents an “all-in” energy and capacity price for must take resources for which energy production is delivered exclusively to the PX marked.19. The PX day-ahead price, adjusted by the Section 390(d) capacity subtracter, reflects some capacity value.20. The ISO’s spinning reserve and non-spinning reserve markets are capacity reserve markets.21. The ISO’s spinning reserve and non-spinning reserve prices reflect the addition of an added increment of production on reserve margins and reliability.22. Adoption of a 50/50 weighting of ISO spinning reserve and non-spinning reserve price as the capacity subtracter would have resulted in an energy price 12 to 59% lower than the PX day-ahead price over the comparison period.23. There are a number of valid ways to allocate system line losses.24. No remote QF solely serving local load was identified.25. CCC’s bifurcated line losses methodology maximizes QF SRAC payments.26. The GMM methodology may be revised from time to time by FERC.27. The PX clearing price reflects the system average GMM.28. For a QF paid under the Section 390(b) transition formula, the GMM must be adjusted by the system average GMM.29. Even if large amounts of energy are purchased outside of the PX day-ahead market, the PX day-ahead price may still represent a reasonable approximation of utility avoided cost.

- 44 -


Conclusions of Law1. CCC’s June 14, 2000 Motion to Set Aside Submission should be granted.2. Appendix A to CCC’s June 14 Motion should be marked as Exhibit 29 and received into evidence as of June 14, 2000.3. SCE’s June 14, 2000 Motion to Strike should be denied.4. CCC’s June 21, 2000 Motion to Strike should be denied.5. QF pricing must comply with both the requirements of PURPA and the Public Utilities Code.6. Payments to QFs must reflect the full avoided cost of the utility purchasing the QF power.7. Adoption of a monthly weighted-average PX-based price complies with PURPA.8. Section 390(c) requires that SRAC energy payments be based upon the PX clearing price.9. The proposal to use the day-ahead PX clearing price for QF energy payments complies with Section 390(c).10. Because the utilities are required to buy the majority of their electricity from the PX, the PX day-ahead clearing price is a reasonable measure for utility avoided cost.11. The PX zonal day-ahead clearing price (adjusted consistent with Section 390(d)) should be adopted as the QF SRAC energy price.12. The societal benefits associated with resource diversity and environmentally preferred energy production by wind and run-of-river hydro QFs outweighs the ratepayer cost of FPL’s proposal.13. Wind and run-of-river hydro QFs should be allowed to elect, at their option, to receive a monthly weighted-average PX day-ahead price (adjusted consistent with Section 390(d).

- 45 -


14. The Commission must comply with Section 390(d), even if it believes such law conflicts with PURPA.15. Section 390(d) defines the value of capacity for purposes of calculating SRAC payments to QFs.16. As-available capacity payments should be eliminated.17. The 50/50 weighting of ISO spinning reserve and non-spinning reserve prices is a reasonable measure of capacity value.18. Using GMMs is one reasonable way to allocate system line losses.19. Proposals to modify the GMM methodology should be directed to FERC.20. The Commission should adopt the GMM of each QF as its transmission loss factor once QFs are paid a PX-based energy price.21. Until QFs are paid a PX-based energy price, the transmission loss factor should be GMM QF/GMM SYS.22. QFs who have elected to switch to a PX-based SRAC should have the GMM of each QF applied as its transmission loss factor, effective immediately.23. We should adopt distribution loss factors based on the WDAT for SDG&E and SCE and of 1.000 for PG&E which will be multiplied by the TLF to arrive at the total loss factor for distribution level QFs.24. In order to determine that the PX is functioning properly under Section 390(c), the PX day-ahead market must provide an ongoing market clearing price, and the PX day-ahead market must be the market where utilities procure the majority of energy for their customers, and the PX day-ahead market must reasonably represent the costs of other utility purchases. If the PX is that market, then it

- 46 -


represents the utilities’ avoided cost, and it is functioning properly for purposes of QF payments.25. Parties should address posting procedures in Phase 2.26. Parties should be prepared to address any required revisions to accounting procedures at the Phase 2 prehearing conference.27. Implementation costs should be evaluated for reasonableness along with other QF contract administration issues in the Annual Transition Cost Proceeding.28. No true-up for QFs paid subject to D.99-11-025 is required.29. This decision applies to all respondent utilities.

O R D E R

IT IS ORDERED that:1. In Phase 2, the Commission shall determine whether the requirements of Pub. Util. Code § 390(c), as further set forth in Conclusion of Law 24, have been met. The assigned Administrative Law Judge shall convene a prehearing conference within 45 days of the effective date of this order to establish a schedule for Phase 2.2. Upon the Commission making appropriate findings in Phase 2, qualifying facilities receiving firm capacity payments, forecast as-available capacity payments, or forecast as-delivered capacity payments from respondent utilities shall be paid the Power Exchange (PX) zonal day-ahead clearing price (adjusted consistent with Section 390(d) as set forth in Conclusion of Law 15) as the short-run avoided cost (SRAC) of energy. 3. Upon the Commission making appropriate findings in Phase 2, wind and run-of-river hydro qualifying facilities may elect, at their option, to receive a monthly weighted-average PX day-ahead price

- 47 -


(adjusted consistent with Section 390(d)) in lieu of hourly pricing once the Commission has made the required findings under Section 390(c).4. Upon the Commission making appropriate findings in Phase 2, qualifying facilities receiving as-available capacity payments from respondent utilities shall be paid the PX zonal day-ahead clearing price as the total SRAC of energy. As-available capacity payments shall be eliminated.5. Once qualifying facilities are paid a PX-based energy price, the Generation Meter Multiplier (GMM) of each qualifying facility shall be applied as its transmission loss factor.6. Effective with the first posting following this decision, the transmission loss factor shall be GMM QF/GMM SYS.7. Qualifying facilities who have elected to switch to a PX-based price shall have its GMM applied as its transmission loss factor, effective immediately.

- 48 -


8. Effective with the first posting following this decision, distribution loss factors shall be based on the Wholesale Distribution Access Tariff for San Diego Gas & Electric Company and Southern California Edison Company and shall be 1.000 for Pacific Gas and Electric Company. The distribution loss factor shall be multiplied by the adopted transmission loss factor to arrive at the total loss factor for qualifying facilities connected at the distribution level.

This order is effective immediately.Dated , at San Francisco, California.

- 49 -


APPENDIX AList of Appearances

************ APPEARANCES ************

Linda Sherif Attorney At Law ALCANTAR & ELSESSER ONE EMBARCADERO CENTER, SUITE 2420 SAN FRANCISCO CA 94111 (415) 421-4143 [email protected] For: COGENERATION ASSOCIATION OF CALIFORNIA (CAC) and EPUC

Evelyn Kahl Elsesser Attorney At Law ALCANTAR & ELSESSER LLP ONE EMBARCADERO CENTER, STE 2420 SAN FRANCISCO CA 94111 (415) 421-4143 [email protected] For: ENERGY PRODUCERS AND USERS COALITION (EPUC)

Michael Alcantar Attorney At Law ALCANTAR & ELSESSER LLP 1300 SW 5TH AVENUE., SUITE 1750 PORTLAND OR 97201 (503) 402-9900 [email protected] For: COGENERATION ASSOCIATION OF CALIFORNIA

Jim Crossen AUTOMATED POWER EXCHANGE, INC. TECHMART 5201 GREAT AMERICA PARKWAY, SUITE 552 SANTA CLARA CA 95054 (408) 517-2100 [email protected] For: AUTOMATED POWER EXCHANGE, INC.

Lisa G. Urick Attorney At Law CALIFORNIA POWER EXCHANGE CORPORATION 200 S. LOS ROBLES AVENUE, SUITE 400 PASADENA CA 91101-2482 (626) 537-3328 [email protected] For: CALIFORNIA POWER EXCHANGE

R. Thomas Beach CROSSBORDER ENERGY 2560 NINTH STREET, SUITE 316

Lindsey How-Downing STEVEN F. GREENWALD, LAURA O'CONNOR Attorney At Law DAVIS WRIGHT TREMAINE LLP ONE EMBARCADERO CENTER, STE 600 SAN FRANCISCO CA 94111-3834 (415) 276-6528 [email protected] For: CALPINE CORPORATION

Douglas K. Kerner Attorney At Law (Of Counsel) ELLISON, SCHNEIDER & HARRIS, LLP 2015 H STREET SACRAMENTO CA 95814 (916) 447-2166 [email protected] For: INDEPENDENT ENERGY PRODUCERS ASSOCIATION (IEP)

Brian T. Cragg Attorney At Law GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP505 SANSOME ST., SUITE 900 SAN FRANCISCO CA 94111 (415) 392-7900 [email protected] For: CAITHNESS ENERGY

James D. Squeri BRIAN T. CRAGG Attorney At Law GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP505 SANSOME STREET, SUITE 900 SAN FRANCISCO CA 94111 (415) 392-7900 [email protected] For: MONSANTO CO.

Beth Dunlop GRUENEICH RESOURCE ADVOCATES 582 MARKET STREET, SUITE 1020 SAN FRANCISCO CA 94104-5305 (415) 834-2300 [email protected] For: FPL ENERGY, LLC

Dian M. Grueneich Attorney At Law GRUENEICH RESOURCE ADVOCATES 582 MARKET STREET, SUITE 1020


BERKELEY CA 94710 (510) 649-9790 [email protected] For: WATSON COGENERATION COMPANY

SAN FRANCISCO CA 94104 (415) 834-2300 [email protected] For: FPL ENERGY, LLC

Edward W. O'Neill Attorney At Law JEFFER, MANGELS, BUTLER & MARMARO ONE SANSOME STREET, 12TH FLOOR SAN FRANCISCO CA 94104-4430 (415) 984-9670 [email protected] For: EL PASO MERCHANT ENERGY, L.P.

Tandy Mcmannes KJC CONSULTING COMPANY 2938 CROWNVIEW DRIVE RANCHO PALOS VERDES CA 90275 (310) 832-3681 [email protected] For: KRAMER JUNCTION OPERATING COMPANY

Sara Steck Myers Attorney At Law 122 - 28TH AVENUE SAN FRANCISCO CA 94121 (415) 387-1904 [email protected] For: ENRON WIND CORP., CENETER FOR ENERGY EFFICIENCY AND RENEWABLE TECHNOLOGIES (CEERT)

Alice Reid PACIFIC GAS AND ELECTRIC COMPANY 77 BEALE STREET SAN FRANCISCO CA 94105 (415) 973-2966 [email protected] For: PACIFIC GAS AND ELECTRIC COMPANY (PG&E)

John J. Prevost PACIFIC LUMBER COMPANY 125 MAIN STREET SCOTIA CA 95565 (707) 764-4280 [email protected] For: PACIFIC LUMBER COMPANY

James Ross RCS CONSULTING, INC. 500 CHESTERFIELD CENTER, SUITE 320

Julio Ramos Legal Division RM. 4300 505 VAN NESS AVE San Francisco CA 94102 (415) 703-4742 [email protected] For: OFFICE OF RATEPAYER ADVOCATES (ORA)

Edward E. Maddox SEAWEST WINDPOWER, INC. 1455 FRAZEE ROAD, NINTH FLOOR SAN DIEGO CA 92108-4310 (619) 293-3340 For: SEAWEST WINDPOWER, INC.

E. Gregory Barnes MICHAEL C. TIERNEY, PETRINA M. BURNHAM Attorney At Law SEMPRA ENERGY 101 ASH STREET SAN DIEGO CA 92101-3017 (619) 699-5019 [email protected] For: SAN DIEGE GAS & ELECTRIC COMPANY (SDG&E)

Robert Ellery SIERRA PACIFIC INDUSTRIES 19794 RIVERSIDE AVENUE ANDERSON CA 96007 (530) 378-8179 [email protected] For: SIERRA PACIFIC INDUSTRIES

David M. Norris Attorney At Law SIERRA PACIFIC POWER COMPANY 6100 NEIL ROAD RENO NV 89520-0024 (775) 834-3939 [email protected] For: SIERRA PACIFIC POWER COMPANY (SPPC)

James B. Woodruff SOUTHERN CALIFORNIA EDISON COMPANY


CHESTERFIELD MO 63017 (314) 530-9544 [email protected] For: MIDSET COGENERATION COMPANY

Don Schoenbeck LINDA SHERIF RCS, INC 900 WASHINGTON STREET, SUITE 1000 VANCOUVER WA 98660 (360) 737-3877 [email protected] For: COALINGA COGENERATION COMPANY

2244 WALNUT GROVE AVENUE, SUITE 342, GO1ROSEMEAD CA 91770 (626) 302-1924 [email protected] For: SOUTHERN CALIFORNIA EDISON (SCE)

Michel Peter Florio ROBERT FINKELSTEIN Attorney At Law THE UTILITY REFORM NETWORK (TURN) 711 VAN NESS AVE., SUITE 350 SAN FRANCISCO CA 94102 (415) 929-8876 [email protected] For: THE UTILITY REFORM NETOWRK (TURN)

Steve Felte General Manager TRI-DAM POWER AUTHORITY PO BOX 1158 PINECREST CA 95364 (209) 965-3996 [email protected] For: TRI-DAM POWER AUTHORITY

Patrick Mcdonnell TXU ENERGY SERVICES 900 LARKSPUR LANDING CIRCLE, SUITE 240 LARKSPUR CA 94939 (415) 461-5820 [email protected] For: TXU ENERGY SERVICES

Jerry R. Bloom Attorney At Law WHITE & CASE LLP TWO EMBARCADERO CENTER, SUITE 650 SAN FRANCISCO CA 94111 (415) 544-1100 [email protected] For: CALIFORNIA COGENERATION COUNCIL (CCC)

Joseph M. Karp Attorney At Law WHITE & CASE LLP 2 EMBARCADERO CENTER, SUITE 650 SAN FRANCISCO CA 94111

Michelle Cooke Administrative Law Judge Division RM. 5012 505 VAN NESS AVE San Francisco CA 94102 (415) 703-2637 [email protected]

James Loewen Energy Division AREA 4-A 505 VAN NESS AVE San Francisco CA 94102 (415) 703-1866 [email protected] For: CPUC - ENERGY DIVISION

Edwin Quan Energy Division AREA 4-A 505 VAN NESS AVE San Francisco CA 94102 (415) 703-2494 [email protected] For: CPUC - ENERGY DIVISION

Pearlie Sabino Office of Ratepayer Advocates RM. 4102 505 VAN NESS AVE San Francisco CA 94102 (415) 703-1883 [email protected] For: OFFICE OF RATEPAYER ADVOCATES (ORA)

Gregory A. Wilson Energy Division AREA 4-A 505 VAN NESS AVE San Francisco CA 94102 (415) 703-2159 [email protected]


(415) 544-1103 [email protected] For: CALIFORNIA COGENERATION COUNCIL (CCC)/WATSON COGENERATION COMPANY

********** STATE EMPLOYEE ***********

James Hoffsis CALIFORNIA ENERGY COMMISSION ENERGY TECHNOLOGY DEVELOPMENT DIVISION 1516 NINTH STREET MS-45 SACRAMENTO CA 95814-5512 (916) 653-2922 [email protected]

For: CPUC - ENERGY DIVISION

********* INFORMATION ONLY **********

Daniel W. Douglass Attorney At Law ARTER & HADDEN LLP 5959 TOPANGA CANYON BLVD. SUITE 244 WOODLAND HILLS CA 91367 (818) 596-2201 [email protected]

Edward G. Cazalet AUTOMATED POWER EXCHANGE 5201 GREAT AMERICA PARKWAY SANTA CLARA CA 94054 (408) 517-2100 [email protected] For: SELF

Reed V. Schmidt BARTLE WELLS ASSOCIATES 1636 BUSH STREET SAN FRANCISCO CA 94109 (415) 775-3113 X111 [email protected] For: BARTLE WELLS ASSOCIATES

Scott Blaising Attorney At Law 8980 MOONEY ROAD ELK GROVE CA 95624 (916) 682-9702 [email protected]

Arthur V. O'Donnell CALIFORNIA ENERGY MARKETS 9 ROSCOE STREET SAN FRANCISCO CA 94110-5921 (415) 824-3222 [email protected] For: Media

Alexandre Makler Attorney At Law CALPINE CORPORATION 6700 KOLL CENTER PARKWAY, SUITE 200 PLEASANTON CA 94566 (925) 600-2000 [email protected] For: CALPINE CORPORATION

James L. Mcarthur DAI OILDALE, INC 3300 MANOR DRIVE BAKERSFIELD CA 93308 (661) 393-1618 [email protected]

Andrew Brown ELLISON & SCHNEIDER, LLP 2015 H STREET SACRAMENTO CA 95814 (916) 447-2166 [email protected]

Diane I. Fellman Attorney At Law ENERGY LAW GROUP LLP 1999 HARRISON ST., SUITE 2700 OAKLAND CA 94612 (510) 874-4301 [email protected] For: SELF

Robert T. Boyd ENRON WIND CORP. 13000 JAMESON ROAD TEHACHAPI CA 93561 (661) 823-6734 [email protected] For: ENRON WIND CORP.

Steve Ponder FPL ENERGY, INC., LLC 980 NINTH STREET, 16TH FLOOR SACRAMENTO CA 95814-2736 (916) 449-9596 [email protected] For: FPL ENERGY, LLC


Bill Woods CALPINE CORPORATION 6700 KOLL CENTER PARKWAY, SUITE 200 PLEASANTON CA 94566 (925) 600-2040 [email protected] For: CALPINE CORPORATION

Ed J. Wheless Division Engineer COUNTY SANITATION DIST. OF L.A. COUNTY SOLID WASTER MANAGEMENT DEPT PO BOX 4998 WHITTIER CA 90607-7411 (562) 699-7411 [email protected]

David R. Branchcomb HENWOOD ENERGY SERVICES SUITE 300 NORTH 2710 GATEWAY OAKS DRIVE SACRAMENTO CA 95833 (916) 569-0985 [email protected] For: INDEPENDENT ENERGY PRODUCERS ASSOCIATION (IEP)

Edward J. Tiedemann Attorney At Law KRONICK, MOSKOVITZ, TIEDEMANN & GIRARD 400 CAPITOL MALL, 27TH FLOOR SACRAMENTO CA 95814 (916) 321-4500 [email protected] For: PLACER COUNTY WATER AGENCY

Richard J. Mc Cann M.CUBED 2655 PORTAGE BAY, SUITE 3 DAVIS CA 95616 (530) 757-6363 [email protected]

Robert B. Weisenmiller, Ph.D. MRW & ASSOCIATES, INC. 1999 HARRISON STREET, SUITE 1440 OAKLAND CA 94612-3517 (510) 834-1999 [email protected] For: VARIOUS INTERVENORS

Edward C. Ryan NUTRA SWEET KELCO CO. UNIT OF MONSANTO 2025 E. HARBOR DRIVE SAN DIEGO CA 92113 (619) 595-5996 [email protected]

Robert Szymanski POWERWORKS, INC. 781 THOMAS LANE WALNUT CREEK CA 94596 (925) 934-9812 [email protected] For: POWERWORKS, INC.

Cristina Robinson SOUTHERN CALIFORNIA EDISON COMPANY 2244 WALNUT GROVE AVENUE ROSEMEAD CA 91770 (626) 302-3412 [email protected]


Cliff Rochlin SOUTHERN CALIFORNIA GAS COMPANY 555 W. FIFTH STREET, ML 22A1 LOS ANGELES CA 90013 (213) 244-2451 [email protected] For: SEMPRA ENERGY

Ann Mac Leod WHITE & CASE, LLP TWO EMBARCADERO CENTER, SUITE 650 SAN FRANCISCO CA 94111 (415) 544-1102 [email protected] For: CALIFORNIA COGENERATION COUNCIL

(END OF APPENDIX A)

Date post:	25-Jun-2018
Category:	Documents
Upload:	leduong
View:	212 times
Download:	0 times

docs.cpuc.ca.govdocs.cpuc.ca.gov/word_pdf/AGENDA_DECISION/3609.doc · Web view2005-12-01 · 12....

Documents